When a well is drilled, reservoir drilling fluid (RDF) is circulated within the drilling equipment to cool down and clean the drill bit, remove the drill cuttings out of the well bore, reduce friction between the drill string and the sides of the borehole, and form a filtercake in order to prevent fluid leak off into the formation. The driving force for the formation of the filtercake is the higher wellbore pressure applied to maintain the borehole stability. This filtercake restricts the inflow of reservoir fluids into the wellbore during the drilling process and placement of the completion. If the filtercake damage that is created during the drilling process is not removed prior to or during completion of the well, a range of issues can arise when the well is put on production, i.e., completion equipment failures and impaired reservoir productivity.
Drilling fluid (mud), also called reservoir drilling fluid (RDF), can be synthetic/oil based or water based. To minimize invasion of the drilling fluid into the formation, both oil based and water based mud filtercakes typically contain a bridging or weighting agent, usually particles of calcium carbonate, barite or a mixture of the two, that bridge at the pore throats of the formation and thereby form a relatively low permeability filtercake. Both oil based and water based mud filtercakes also contain solids called cuttings that have been picked up during drilling, as opposed to the bridging/weighting agents that are added in the formulation of the drilling fluid. These solids can be quartz (sand), silts and/or shales, depending on the reservoir formation as well as the formations traversed by the drilling path to the reservoir. In addition, oil based drilling muds contain water droplets that become trapped in the pore space of the filtercake, while water based mud filtercakes contain polymers, such as starch and xanthan gum, and other inorganic salts.
The formation of a mud filtercake is often necessary for drilling, particularly in unconsolidated formations with wellbore stability problems and typically high permeabilities. However, from a production standpoint, the filtercake is certainly undesired. In certain types of completions, it is possible to produce hydrocarbons from these formations without performing any type of filtercake cleanup treatments. In other cases, as described in Brady et al., SPE 63232 (2000), a filtercake cleanup may be necessary to achieve the target production rates. Furthermore, although in some instances it is possible to produce hydrocarbons without any filtercake cleanup treatments, it is impossible to inject into the formation without a fracturing operation unless a cleanup treatment is performed. Such a fracturing operation is often undesirable. See Parlar et al., SPE 77449 (2002).
Conventional filtercake removal treatments use an array of chemicals specifically targeting two of the three components of the water-based RDF filtercake: (1) chelants or acids to dissolve the calcite component; and (2) enzymes or oxidizers to degrade the polymer component. For example, well treatment fluids for filtercake removal in gravel packing, available under the trade designation MudSOLV and described in U.S. Pat. No. 6,638,896 and U.S. Pat. No. 6,140,277, both to Tibbles et al., use a gravel carrying fluid containing enzyme for polymer removal in filter cake remediation, chelating agent to dissolve carbonate, and a viscoelastic surfactant (VES) system at a sufficiently high concentration to viscosify the fluid. However, these treatments fail to dissolve the third component of the water-based RDF filtercake, i.e., the drilling solids and clays. Removal of the bridging agents and polymeric components from the filtercake is often not sufficient to achieve acceptable injection rates. U.S. Pat. No. 6,978,838 discloses a three-step process to remove the filtercake by sequentially treating to remove each of the filtercake components, but does not disclose a method or composition for an effective single-fluid treatment to remove filtercake.
In the completion of injection wells, while the operators are pulling off the tools after perforation, screen placement or the like, the system can be under differential pressure and then once cleared, the valve is closed and a shut in period starts; during this time, the cleaning solution is reacting with the filtercake and dissolving the filtercake. Thus, a requirement for an effective filtercake treatment in injection wells would be that the treatment fluid dissolves the targeted components at a controlled rate while under differential pressure: a complete propagation of the fluid throughout the entire filtercake should be obtained before breakthrough occurs. Otherwise, all of the treatment fluid would go into the formation in regions where the filtercake has already been removed. See Parlar et al., SPE 50651 (1998). While the prior art has attempted and arguably achieved a balance of the trade-off between delayed reaction and complete dissolution for the calcite and polymer portions of the filtercake, there remains an unfilled need in the art for a way to dissolve drilling solids and clays at the same delayed rate.
Conventional mud acid treatment fluids are too corrosive to be used in filtercake removal fluids. Mud acid treatments of 12 weight percent hydrochloric acid (HCl) and 3 weight percent ammonium bifluoride (NH4F:HF), referred to herein by the shorthand notation “12/3,” and 9/1 mud acids (9 wt % HCl, 1 wt % NH4F:HF), have typically been used to dissolve drilling solids and clays. However, these mud acid treatments are so reactive that significant amounts of silicon, aluminum, and calcium are all very rapidly complexed in solution, under differential pressure breakthrough occurs via pinholes formed in a short time period, and the treatment fluid is lost.
The high reactivity of mud acids results in a poor injectivity or permeability because the fluid leakoff leaves the filtercake intact except for the tiny holes, which subsequently become plugged by relatively small particles. Thus, mud acid treatments have resulted in premature pressure build up before any further fluid penetration. To solve this fast reactivity issue in the field, this typical mud acid treatment is injected into an isolated section of the horizontal well to favor complete propagation of the treatment to the entire section before breakthrough, and brine is injected right after the mud acid treatment to dilute the solution in an attempt to avoid corrosion of hardware, such as sand control screens, for example, due to the highly corrosive nature of conventional mud acids. Furthermore, these treatments often require relatively large quantities of mud acid to ensure contact even in isolated sections, as well as long rig times, which lead to very high cost particularly in deepwater environments.
There is a need in the art for mud acid type treatment fluids that can clean the filtercake in a single step to establish injectivity, but which are much less corrosive than the typical 12/3 or 9/1 mud acid treatments previously used in the field. Such a fluid would desirably have an optimum balance between a high dissolving power to have significant dissolution, but not too high to avoid premature leak-off under differential pressure.